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Building Support for the “Arctic” Project November 18, 2002 Houston, Texas, USA Jim Harrington

Building Support for the “Arctic” Project November 18, 2002 Houston, Texas, USA Jim Harrington Houston Energy Group, LLC. “Arctic” Project: Briefing Outline. ENVIRONMENT Gas Supply Options Gas Value Chain ARCTIC STUDY History, Scope and Conclusions Route Options

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Building Support for the “Arctic” Project November 18, 2002 Houston, Texas, USA Jim Harrington

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  1. Building Support for the “Arctic” Project November 18, 2002 Houston, Texas, USA Jim Harrington Houston Energy Group, LLC

  2. “Arctic” Project: Briefing Outline ENVIRONMENT • Gas Supply Options • Gas Value Chain ARCTIC STUDY • History, Scope and Conclusions • Route Options • Supply/Demand Assessment • Economic Assessment • Environmental Considerations • Technological Advancements • Regulatory Challenges • Findings/ Recommendations/ Conclusions BEYOND THE STUDY • New ‘Project’ Matters • Building Project Support • This briefing is not advocating Alaska versus Mackenzie, or ‘Over the Top’ versus TransAlaskan pipeline route. Its about: • ENVIRONMENT – understanding the Arctic competition • ARCTIC STUDY – understanding the Arctic Project • BEYOND THE STUDY – positioning to optimize the Arctic result. Houston Energy Group 2

  3. Environment: Gas Supply Options • A complete turnaround from • the last Arctic discussion: • For every 1 Tcf consumed since 1990 3.4 Tcf have been proven. • Reported proven global natural gas reserves surpassed oil in 2001; double on a reserve life index (RLI) basis. • Monetization of stranded gas via LNG, GTL, etc. is increasing in country/company priority. • Competing projects (e.g., LNG) continue to come down in cost - improving their competitiveness. 3 Houston Energy Group

  4. Environment: LNG Options There are 15 operating LNG plants in 12 countries (shown as darker circles) with many more planned, and some under construction: Norway, Egypt, Malaysia III and with new contracts: Indonesia – Tangguh. 10 of the 12 countries with LNG plants are expanding liquefaction capacity (but not Alaska, Libya). Dark countries import LNG, and shaded countries are considering it. The large numbers represent where the proposed new plants are. 20 19 16 2 1 2 2 9 18 20% 20% 1 5 4 2 15 3 11 60% 13 14 8 6 3 15 22 23 1 24 12 9 4 21 8 10 7 13 17 5 11 8 14 7 12 6 10 5 6 Nigeria II Egypt: Idku Yemen: Bal Haf Egypt: Damietta Papua New Guinea Australia: Gorgon Australia: Bayu Undan Australia: Sunrise Russia: Sakhalin II Irian Jaya: Tangguh Angola: Luanda Bolivia: Margarita Brazil: Amazon Peru: Camisea Iran: South Pars Norway: Snohvit Indonesia: Natuna Canada: Hibernia Russia: Yamal Alaska: North Slope Equatorial Guinea: Alba Venezuela I: Shell Venezuela II: BG Nigeria – West Delta 1 5 9 13 17 21 2 6 10 14 18 22 7 11 15 19 23 3 4 8 12 16 20 24 4 Houston Energy Group

  5. Environment: LNG Capacity - liquefaction Includes some expansion at existing terminals and some new terminals. Currently Oman, Malaysia, Australia, Qatar and Trinidad & Tobago, etc. are building LNG spec. capacity. The existence of excess gas supply and an open access US receiving terminals are feeding this. Slope = 12.9 MMtpy, more than double the 90’s Does not included: Angola-Luanda Brazil-Amazon Equatorial Guinea-Alba Peru-Camisea Venezuela-PVLNG AU: Gorgon AU/E Timor: Sunrise AU: Scotts Reef Indo: Natuna Iran: South Pars Nigeria: W. Delta Canada: Hibernia Alaska: North Slope Papua New Guinea Russia: Yamal Etc. At existing terminals does not include these expansions: Trinidad #5,6 = 8 Nigeria #6 = 4 Qatargas #5,6 = 9.5 Rasgas #5,6 = 7 TOTAL = 28.5 MMt The following 7 countries have announced they want to be the largest LNG supplier (about 40 MMt each): Trinidad & Tobago, Nigeria, Algeria, Qatar, Malaysia, Indonesia, and Australia. Approximate: 1 MMt = 50 Bcf 1 Tcf = 20 MMt 5 Houston Energy Group

  6. Environment: LNG Capacity - Shipping Recently there has been a shortage of LNG ships (for example, this reduced the LNG available to US in the 2000 year because of high US gas prices then). There are 132 ships now, up from 118 a year ago. Current ships being built (industry capacity = 28/year with 3 years to build) will greatly exceed the LNG growth as this supply chain unbundles and the entrance of more companies wanting to own their ships. Currently 6 to 8 ships being built per year that are not dedicated to a LNG project. LNG Ship Surplus 6 Houston Energy Group

  7. Environment: LNG Capacity – US Receiving When Cove Point goes into operation in 2003 capacity will be 2.7 Bcf/d, with plans to expand to 4.45 Bcf/d. Hackberry, La. application (CP02-374) for 1.5 Bcf/d and many others (more than 20) are being planned in Canada, US, Bahamas and Mexico. LNG has averaged about 0.65 Bcf/d the last three years, so there is substantial upside without significant additional facilities. 7 Houston Energy Group

  8. Environment: LNG Value Chain During this decade the LNG market will be in a position of excess supply and capacity. In addition, its cost to deliver continues to decrease with further decreases expected going forward … table is illustrative only – to US some LNG sites are lower and some are higher. Arctic failed in the 1970s because of domestic production gains. Will it be International gas this time? Ships give LNG projects the opportunity to switch gas markets - an advantage. Excess Capacity Excess Capacity Excess Capacity Excess Supply 8 Houston Energy Group

  9. Environment: North American Gas Supply The competitive alternatives to Arctic gas today are greater than they were in the 1970s. In addition, by pipeline: Canadian Hibernia, Colombia and Venezuela gas reserves are ‘closer’. At gas prices between $2.75 and $3.75 (Chicago Hub) there are a growing number of potential supply sources. • WestSupplyEast • LNG: North Slope Sable Is. • Alaska (?)Mackenzie Delta Hibernia • Existing LNG CS – WCSB LNG: • Bolivia Deep Gulf of Mexico • Trinidad • Peru CS – US Rockies • Venezuela • Timor Sea Colombia • Algeria • Irian Jaya Venezuela • Nigeria • Indonesia-Natuna Others • Angola • Papua New Guinea • Egypt • Sakhalin Is. • Norway • Gorgon • Middle East • Canada (?) • Eq. Guinea • Others (?) • Others(?) Into supply connects to markets CS = Coal seam methane 9 Houston Energy Group

  10. Environment: North American Gas Demand Gas demand in NA (US, Canada, Mexico) was approximately 27 Tcf in 2001 (same as 2000), and is forecast to approach 38 Tcf by 2020. Our projection is more conservative than some as it reduces industrial demand for ammonia, methanol and other gas intensive industries. At $3.00+ gas prices – these businesses will go elsewhere (next to a LNG plant). This demand will not be realized at prices above $4.00. Mexico Canada, Alaska US L48 States 10 Houston Energy Group

  11. “Arctic” Study: History, Scope, Conclusions We performed a thorough study of Arctic gas options into North America a year ago, and it has been updated since then. That study concluded that the project was commercial, competitive, and was possible under existing technologies, environmental and regulatory requirements. Some results were published in the Oil & Gas Journal then and I will update then for you now. HISTORY Study 1st done in 2001 for INGAA Foundation. • The Foundation is represented by US and Canadian pipelines and their suppliers. • HEG and URS Corporation prepared the Study Study updated by HEG • North American supply options, demand levels, and price • North American infrastructure requirements SCOPE, CONCLUSIONS • Environmentally Feasible … YES • Technically Feasible … YES • Regulatorially Feasible … YES • Commercially Feasible … YES • Competitive … YES All deal killers were within the control of the Arctic participants 11 Houston Energy Group

  12. “Arctic” Study: Route Options Studied SIX OPTIONS STUDIED --- Proposed ANGTS --- Proposed Dempster Lateral --- Proposed Mackenzie Valley --- ‘Over the Top’ --- Northern – Onshore --- TAGS (LNG) 12 Houston Energy Group

  13. “Arctic” Study: Gas Price Forecast • We support a sustainable $2.75-$3.75 price range. • In the 1990s Henry Hub spot gas price averaged 64% of WTI: • $2.05/MMBtu v $19.16/Bbl. • Due to technology (CCGT generation) and environment drivers we forecast gas prices to rise to 75% of oil price in NA on an energy basis. • $19.16/Bbl  $2.40/MMBtu • $24/Bbl  $3.00/MMBtu • US gas prices have averaged above 70% of oil since 1995. Oil / 6 Gas Current Year Prices 13 Houston Energy Group

  14. “Arctic” Study: Supply and Demand • Infrastructure as key as supply. • In 2001 > 90% (i.e. 69 out of 75 BCF/d) of gas from ‘Supply’ zone. • 50% of gas demand came from provinces and states east of this ‘Supply’. • Lines indicate additional supply sources. • Key finding: need for additional pipeline capacity from ‘Supply’ to east and west coast markets. Pipeline routes and access through Ontario and Ohio are key to retaining an integrated gas market. 14 Houston Energy Group

  15. “Arctic” Study: Gas Supply Options The table on top summarizes the sources modeled to meet the projected increase in demand. This study was done on a basin-by-basin, LNG plant-by-LNG plant basis, and assumed pipeline infrastructure would be built (big assumption). Source of Incremental Gas to US Source: 2001 GTI Baseline for 2020 15 Houston Energy Group

  16. “Arctic” Study: Gas Reserve Compared to 2000 NA consumption of 27 TCF, or Reserve Life Index (RLI) = 14 with Arctic reserves connected, up from 11. Arctic gas reserves are proportionately greater than Arctic oil reserves were back when the oil pipeline was built from the North Slope in the 1970s. 16 Houston Energy Group

  17. “Arctic” Study: Commercial Advantages • Domestic source • Liquid content  lower oil imports • Gas demand for enhanced oil from tar sands production • Lowers NAFTA dependence on oil imports • Common ownership between gas reserves and tar sands reserves • Arctic gas delivered into supply grid: • More market choices • Improves reliability of integrated network Location of Alberta Tar Sands 17 Houston Energy Group

  18. “Arctic” Study: NAFTA Energy Balances • NAFTA imports more than 1/3 of its liquid petroleum requirements. • A tripling of Alberta tar sands oil production to 2 million barrels per day would lower NAFTA’s net liquid imports 20% everything else being equal (and potentially consume 1.5 Bcf/d … ideally from the Arctic). 18 Houston Energy Group

  19. “Arctic” Study: Study Regions 10 Study Regions: 1 – Arctic 2,3 – Canada 4-9 – US (EIA’s 6 regions) 10 - Mexico 19 Houston Energy Group

  20. “Arctic” Study: 2000 Gas Balance and Flows • This chart shows the difference between annual supply and demand in each of the 10 study regions, and the average day flows between regions, in year 2000 (BCF/d.) 2000 Demand In TCF: Canada 2.9 L48US 22.8 Mexico 1.3 Total 27.0 20 Houston Energy Group

  21. “Arctic” Study: 2015 Gas Balance and Flows • This chart shows the same difference between annual supply and demand in each region, and the average day flows between regions - in 2015 (using the study assumptions) 2015 Demand In TCF: Canada 4.1 L48US 29.5 Mexico 2.3 Total 35.9 21 Houston Energy Group

  22. “Arctic” Study: Change in Balance & Flows • This chart shows the difference between 2000 and 2015, or the change in demand and supply by region, and the average day interregional flows needed to meet demand. Increase in Demand (TCF): Canada 1.2 L48US 6.6 Mexico 1.0 Total 8.9 22 Houston Energy Group

  23. “Arctic” Study: New Infrastructure Needed • Average day data needs to be converted to peak day to measure the amount of new pipelines needed. • We did this using assumptions of peak day demand. We need the Equivalent of 4 new Alliance Pipelines to the Northeast within 15 years 23 Houston Energy Group

  24. “Arctic” Study: Comparing Project Economics Only Pipeline Options Shown • Project economics to Boundary Lake, Alberta • Desktop study using industry best practice adjusted upward for environmental, technical, other factors identified in Study. • Annual Operating Cost includes return on and of investment at 70/30 D/E. Annual Unit Rate Capacity Capital Operating @ 95% LF Project BCF/d $Bn $Bn $/MCF ANGTS 4/6 $10/$13 $1.5/$1.95 $1.08/$0.94 Dempster Lateral 2 $3.5 $0.5 $0.72 Mackenzie Valley 2/4 $4/$5.5 $0.6/$0.8 $0.87/$0.58 Over-the-Top 6 $13 $1.95 $0.94 Onshore Prudhoe- Mackenzie 6 $12 $1.80 $0.87 24 Houston Energy Group

  25. Arctic Commerciality ($ Per MMBtu) Pricing Point Price Explanation Chicago Hub $3.50 Assumed long-term contract price Alberta/British Columbia Border $2.60 Alliance Pipeline tariff used as an example Arctic Wellhead $1.60 Wellhead Netback Price “Arctic” Study: Positive Economic Assessment • Table showing producer netback in Arctic using study pipeline cost assumption at $1.00 per Mcf. • Arctic project requires $3.00-$4.00 per MMBtu gas price. • Below $3.00 and producer netback unlikely to be attractive. • Above $4.00 and gas demand is unlikely to be adequate. • New pipeline capacity is needed to the markets (east and west coasts) … which the study quantified. Note – this wellhead price is higher than assumed with ‘illustrative’ LNG project. 25 Houston Energy Group

  26. Arctic Pipeline Liquids Category Amount Explanation Assumed Gas Production 6.0 BCF per Day Available Liquid Heat Content 0.1 100 BTUs per MCF assumed extracted as liquids in Alberta Liquids Extracted 0.6 BCF equivalent per Day Liquids 100,000 Barrels per Day assuming 6 MCF per Barrel “Arctic” Study: Positive Economic Assessment • Note – Does not include ‘Alliance’ technology in pipeline design. • Arctic gas production would also increase domestic liquids production ... Here is an illustrative calculation. 26 Houston Energy Group

  27. “Arctic” Study: Environmental Considerations • Key environmental issues: • Environmental discharge, • Oil spills and cleanup, • Cumulative effects of development, • 4) Effects on subsistence lifestyles of native • communities, and • Inclusion of traditional knowledge Our study identified the key environmental issues that needed to be addressed in a Arctic type project. We also identified the special considerations that such a pipeline would need to consider. These were based on current requirements, and not those in existence when ANGTS was approved. Our study included known Mitigation measures and options for these issues and considerations. • Special considerations include: • Endangered species, • Subsistence hunting, • Seasonal construction/repair, • Permafrost, • Ice gouging, • Leak detection, and • Strudel scour 27 Houston Energy Group

  28. “Arctic” Study: Technology/Process Gains Design and Construction: 1) High strength steels 2) Design changes 3) Construction in frozen land improvements 4) Automated ultrasonic testing 5) Directional drilling under rivers and streams 6) Composite reinforced line pipe Our study identified new technologies for both design and construction as well as ongoing operations and maintenance. Our focus here was on technologies during the past decade rather than going back too far that could be applicable to Arctic projects. Operation & Maintenance: 1) GIS 2) Inline inspection tools 3) Electronic flow measurement and automated operations 4) SCADA data analysis 28 Houston Energy Group

  29. “Arctic” Study: Regulatory Complexity The regulatory complexity for an Arctic project is higher than most pipelines to-date. This chart for the Mackenzie Valley Pipeline route … possibly the least complex because it only involves two Canadian provinces. Illustration of regulatory complexity Regulatory collaboration, coordination and compromise are critical success factors: • Mackenzie Valley Pipeline • June 2002 Cooperation Plan • MOU – Invialuit participation in • environmental review (10/1) • Draft EIR – Environmental Impact • Review public (10/7) 29 Houston Energy Group

  30. Potential Landowner Benefits • Access roads, bridges • Erosion control, ponds, parks • Cultural, endangered species data • Direct property owner payments • Property taxes • Equipment rental, consumables • Local employment, training “Arctic” Study: Regulatory Challenges Key hurdle Native land access & land claims. A very important element in any Arctic pipeline is successfully dealing with Native issues, which are substantial, but so are the potential benefits … a case of finding the win-win solution “early” before sides are taken. Feasible, but certainly the most challenging the industry has faced. 30 Houston Energy Group

  31. “Arctic” Study: Some Key Findings Again, we found Arctic was feasible from a regulatory, technical and environment perspective. Our analysis of the project Provided higher netback at the wellhead compared to the competition. • Environment  Feasible • Unique to Arctic • Mitigation and monitoring • Technology  Feasible • Since ANGTS: significant advances, including experience with TAPS • Liquids rich gas a la Alliance • Competitive  Feasible • Netback comparable • Enhance oil from tar • Regulatory  Feasible • Multi-jurisdictional: Collaboration, Coordination and Compromise required • Key Hurdle: Native land access & land claims • Economic  Feasible • $3-$4 at Chicago • Market ‘beyond’ Chicago 31 Houston Energy Group

  32. Challenges to Arctic Gas Challenge Controllable Ensure land access and land claims for First Nations are resolved Yes Pipeline Infrastructure Delays Yes Respect for land, environment, wildlife and traditional lifestyles Yes “Arctic” Study: Some Key Findings • Suggested Actions to meet • these challenges: • Regional development with Arctic communities, • Educate and train Arctic workers, • Coordinated infrastructure development policy across North America • The study did not focus on • legislative solutions to • address commercial risk • to the commodity. That did • not appear needed. 32 Houston Energy Group

  33. “Arctic” Study: Some Conclusions We agree that pipeline capacity is needed beyond Alberta, but that is not specifically an Arctic requirement. LNG plants do not talk about additional pipeline investment past the receiving terminal … they don’t have to … its an integrated gas market. • North America needs new supply sources • Arctic is significant, new domestic supply • Feasible – Technical, Environmental, Regulatory • Key – Invest in Arctic region and its people • Key – Coordination, collaboration, compromise • North America needs new pipeline capacity • This capacity is needed to east and west coasts • Key – Access to new right-of-way to market 33 Houston Energy Group

  34. Beyond the Study: New Project Matters Our study didn’t cover matters that need to be addressed. Legislative solutions ignores that other projects are proceeding without such benefit, and that there is more than enough gas around … the issue is infrastructure. It may be best for NA to keep the Alaskan/Arctic gas up there as a deterrent to future security of supply risks … why consume all of ours like we are with oil. • New Project matters: • Alternative Arctic routes are competing against each other rather than developing a comprehensive, acceptable approach = all will lose at the current pace (except a downsized Mackenzie). • 45 Tcf proven (and much more likely) makes regulated pipeline returns acceptable for that industry. • Alternatives (e.g., LNG) are bringing their costs down rapidly and could displace Arctic (as occurred before). There is more than enough gas. • $20 Billion cost (or more or less) may be required to get the gas to the Chicago Hub, but that is not the challenge of the Arctic gas … NA has an integrated gas market. If WCSB starts to decline post 2012, then the pipe to Chicago may not be as big. 34 Houston Energy Group

  35. Beyond the Study: To Chicago? • Clearly, a pipeline to Chicago • will miss the benefits of • other gas markets when the • basis differential out of • Alberta favors other • locations. • Through convergence Arctic • gas can become (examples): • Injected gas for tar sands • gas or power in Alberta • gas or power in West • gas or power in East • power export to US • feedstock in petrochemical • Its not just about gas price • any more. • To Chicago?: While capacity is needed to achieve • the forecast growing market, that is not efficiently • done within the Arctic project: • Once an Arctic project is under construction, pipeline companies will have the incentive to add takeaway capacity from AECO to markets east and west • The future decline rate of WCSB could influence additional AECO requirements, which is not known at this time Top of Both Curves $/MWh Electricity Pool Price Gas Price equivalent* Time * including thermal efficiency 35 Houston Energy Group

  36. Beyond the Study: Arctic versus Competition • Benefits of Arctic: • Security of Supply: Reduce dependence on imported energy – increase domestic gas production • Environment: Decrease domestic emissions of carbon dioxide (through fuel substitution) • Security of Supply: Increase proportion of long-life domestic gas production • Price: Long-term price stability since investment in place • Price: Reduce commodity price volatility • Macro Economic: Benefit US and Canadian economies, including from construction, a new development corridor, and from price impacts on the economy • Oil Imports: Increases domestic liquids production • direct via NGLs • indirect via Alberta Tar Sands • Hydrates: Access to methane from ice hydrates in NWT • This is a comparison between Arctic gas and any/all LNG imports. 36 Houston Energy Group

  37. Beyond the Study: Building Project Support • One Arctic approach, one Arctic project. • New Project approach: • Two Arctic pipelines is better than 1 (and 0). • Deal with real Arctic issues – local requirements, etc. as identified in our study – collectively. • Develop markets close to the supply (e.g., Tar Sands to lower oil imports) to improve overall returns and gas market impact. • Emphasize real Arctic value – domestic production for a long time = Security of Supply that alternative don’t provide (and ships can go anywhere). 37 Houston Energy Group

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